Concept Select Update

3 March 2021

 

Jersey Oil and Gas plc

("Jersey Oil & Gas", "JOG" or the "Company")

 

Greater Buchan Area Development Project

Concept Select Update

 

"Potential for 172 MMboe 2C contingent resource estimates to be developed from a fully electrified platform"

 

Jersey Oil & Gas (AIM: JOG), an independent upstream oil and gas company ‎focused on the UK Continental Shelf ("UKCS") region of the North Sea, is pleased to announce the key findings of its detailed and comprehensive Concept Select Report ("CSR") in respect of its Greater Buchan Area ("GBA") Development Project which contains an aggregate 172 million barrels of oil equivalent ("MMboe") 2C contingent resource estimates of light sweet crude and associated gas. The planned development is centred on resuming production at the Buchan oil field and producing the J2 and Verbier oil discoveries as well as other existing and yet to find discoveries within the GBA as future upside.

 

Highlights

 

-    A three-phase development centered around a single integrated wellhead, production, utilities and quarters platform located at the Buchan field - the GBA hub

-     The development concept is based on P50 Technically Recoverable Resource estimates of, in aggregate, 172 MMboe of light sweet crude and associated gas within the Core GBA, which includes the Buchan oil field and J2 and Verbier oil discoveries

-     JOG aims to deliver production from the planned GBA Development Project at an industry leading carbon intensity level due to Platform Electrification, as seen in certain fields in the Norwegian sector

o  Overall carbon emissions from the GBA with platform electrification estimated by management at <1kg/boe

-    Project economic estimates by management for the Core GBA selecting Platform Electrification as our preferred low carbon power solution, are:

o  Pre-tax free cashflow of US$6.4 billion with an NPV (pre-tax) of US$1.7 billion

o  Payback period under 3 years

o  Project internal rate of return ("IRR") greater than 25%

-   Development costs (Capex and Opex) based on today's values are estimated to be approximately US$30/boe

o  Capex estimate for Phase 1 of approximately £1 billion (including 20% contingency)

o  Opex estimate during plateau production of US$8/boe to US$9/boe

-    The GBA hub nameplate capacity has been set at 40,000 barrels of oil per day ("bopd") with expected plateau production of more than 3 years

-    Significant upside potential from 4 drill ready exploration prospects within the GBA that have combined prospective resource estimates totaling an additional 219 MMboe

o  The close proximity of the GBA exploration prospects, will enable their development, on discovery, as low cost subsea tie-backs to the planned GBA hub

o  A discovery in line with P50 estimates at any of the drill ready exploration prospects has the potential to extend plateau production significantly and materially increase project economics

-     With the preferred development concept identified, JOG is now ready to launch its planned and previously announced farm-out process for the GBA

 

A concept select update presentation is also available to download on the Company's website at: www.jerseyoilandgas.com/investors/presentations/ 

Andrew Benitz, CEO of Jersey Oil & Gas, commented:

"The GBA has the scale to be extremely low carbon through platform electrification at the same time as offering highly favourable project economics. As a result of a significant amount of work from Jersey Oil & Gas' excellent project team, working with specialist contractors, consultants and service providers, we are well on track to deliver on our Licence commitment to deliver the Concept Select to the Oil and Gas Authority ("OGA") by July this year.

 

"We now plan to launch a farm-out process, which we expect to be highly attractive to a wide range of oil companies in light of the project's scale, economics and low carbon potential through platform electrification, characteristic of certain fully electrified fields offshore Norway."

 

Summary of Concept Select Findings

Delivering Concept Select has been a comprehensive work effort led by our project team requiring over 14,000 JOG hours and 18,000 contractor hours.  In early 2020, JOG completed an Appraise phase assessment of the various development options for the GBA. This option screening phase concluded that development of the GBA's resources via a fixed production platform located at the Buchan field, offered the optimum solution when considering environmental factors, safety issues, technical feasibility, execution risk, schedule, capital and operating costs, project economics, availability and operability.

 

Subsequently, the Company has progressed this development option through the Concept Select phase, with work commencing in April 2020. The objective of this Select Phase was to deliver a single, economically acceptable concept to develop the GBA in order to take the project forward into the Define Phase.

 

The selected concept for the GBA Development is planned to be executed in three Phases. Phase 1 will deliver a single integrated wellhead, production, utilities and quarters (WPUQ) Platform located at the Buchan field. Production from the reservoirs will be supported by injection of both produced water and seawater. The facility will be normally manned. The Buchan wells will be drilled utilising a heavy-duty jack-up (HDJU) located over a 12 slot well bay. The Phase 1 facilities will be designed to accommodate Phase 2 and Phase 3 of the development. Phase 2 will develop the J2 West, J2 East and Verbier East discoveries via a subsea tie-back to the GBA platform. Phase 3 will develop the Verbier West discovery via connection to the Phase 2 subsea infrastructure.  Field life is anticipated to be 31 years.

 

The Buchan location benefits from close proximity to existing export infrastructure for both oil and gas. Selection of the final oil and gas export routes will be subject to a detailed economic and risk assessment through formal requests for service issued in February 2021. Initial negotiations with pipeline operators will be conducted in accordance with Oil & Gas UK's Infrastructure Code of Practice. It is scheduled that this work will be completed to inform FEED (Front End Engineering and Design), currently planned to take place later this year.

 

Work has also been conducted to identify the optimum type of artificial lift for the production wells.  Gas lift and electrical submersible pumps (ESPs) were investigated. The use of ESPs was shown to deliver a higher production rate and thus greater recoverable volumes over the same period than gas lifted wells.

 

Project Economic and Cost estimates

Cost estimates for each phase have been prepared in accordance with the detailed work break down structures for Phase 1, 2 and 3.  The CAPEX, OPEX and DRILLEX estimates were developed in line with the American Association of Cost Engineers International (AACEI) Class 4, with an expected accuracy of +/- 30%.  CAPEX costs for Phase 1 are estimated to be approximately £1 billion.  Operating costs during plateau production are estimated at US$8/boe to US$9/boe, with a payback period estimated at under 3 years.  Plateau production is estimated for more than 3 years.  Total project costs based on current day values are estimated to be approximately US$30/boe.

 

Summary economic estimates by management for the Core GBA Project selecting platform electrification as the Company's preferred low carbon power solution:

 

Commodity Pricing	Brent	Phase 1	Core GBA
Inflation	(2%)	Nominal	Nominal
Economic Resources	Mmboe	122	162
Life of Field	Years	31	31
CO2 / Production	kg/boe	<1kg	<1kg
Pre-Tax cumulative cash flow	$bn	4.7	6.4
Post-Tax cumulative cash flow	$bn	3.1	4.2
NPV (Pre-Tax)	$bn	1.3	1.7
NPV (Post-Tax)	$bn	0.9	1.1
IRR	%	>25%	>25%
Payback from first oil (years)		1.9	2.8

 

		Phase 1	Core GBA
		Real	Real
CAPEX	$bn	1.4	2.1
OPEX	$bn	2.6	2.7
CAPEX / boe	$/boe	11.1	13.1
OPEX / boe	$/boe	21.0	16.9
ABEX / boe	$/boe	1.6	2.6

 

 

The following economic assumptions have been used in the Company's economic model:

·      An oil price of US$65/bbl in 2021, escalated by 2% per annum from 2022

·      Economic date of 1^st January 2021

·      All costs are referenced to 2021 and inflated by 2% per annum from 1^st January 2022

·      All cost inputs are in GBP and are converted to US$ using a constant foreign exchange rate of 1.3

·      Discount rate of 10%

 

Electrification

In line with the UK Government's Net Zero policies, JOG recognises the need for a low carbon power solution and has an aspiration to deliver production from the GBA Development Project at an industry-leading carbon intensity level. Accordingly, options have been assessed that offer the opportunity to eliminate carbon dioxide emissions associated with power generation on the planned production facility. Economics have been run based on the provision of power from the UK national grid via the installation of a subsea cable to shore.

 

The provision of power from shore offers the opportunity to remove rotating equipment from the offshore facilities along with supporting utilities, e.g. fuel gas treatment equipment. A fully electrified facility also allows for the removal of traditional utility systems such as instrument air. This provides both a CAPEX reduction for the topside facilities and an associated OPEX reduction due to the lower maintenance burden. Removing the requirement to utilise associated gas as fuel also increases gas export revenues. Such CAPEX and OPEX reductions are however offset by the cost of the grid connection and subsea cable and the in-service purchase price of electricity.

 

A "Net Zero" solution for the GBA Development Project is economically attractive, despite a 'Green Premium' compared to the conventional case utilising gas turbines. The costs associated with the provision of a subsea cable and grid connection outweigh the cost reductions associated with the removal of gas turbines and associated utility systems, resulting in a CAPEX increase of approximately £80 million.

 

Overall carbon emissions from the GBA with platform electrification are estimated to be <1kg/boe.  This compares to estimated carbon emissions from the GBA development using gas turbines of 13kg/boe, which is less than the UKCS average of approximately 20kg/boe.

 

The forecast economic outturn for the power from shore case relative to the conventional gas turbine case is based on current UK Government carbon tax forecasts up to 2030 and the cost of sourcing power from the UK. Based on these assumptions, the "Green Premium" results in a project NPV reduction of approximately 8%.

 

The GBA is optimally located in the heart of the UK Central North Sea such that there is exciting potential for JOG to be an enabler for regional electrification.  Collaboration with other regional operators could reduce overall capital costs associated with the cable infrastructure. Additionally early stage engagement with infrastructure funds has indicated that there is potential interest in financing the capital costs in return for future tariff payments.  The Company continues to progress studies that may lead to electrification costs reducing in line with conventional power solutions.

 

A decision to adopt a power from shore case takes into account environmental, social and corporate governance (ESG) and Licence to Operate considerations and details of our Corporate Carbon Policy will be announced shortly.

 

Regional Hub Potential

Collaborative studies conducted in parallel with the GBA Concept Select Phase, have identified the potential for significant synergies with neighbouring, third party discovered resources. The production of such resources through the GBA facility offers the potential for both parties to realise reductions in development costs and OPEX costs offering the potential to increase incremental recovery of oil from the GBA and neighbouring discoveries.

 

JOG continues to seek further collaboration with neighbouring, third party discovered resources, with the aim of providing JOG and owners of neighbouring fields with details of the costs and associated economic outturns for various development scenarios.

 

Future Exploration Upside

As detailed in JOG's announcement of 14^th December 2020, the GBA includes four drill ready exploration prospects, namely Wengen, Cortina, Verbier Deep and Zermatt, which have combined P50 prospective resource estimates of an additional 219 MMboe. An assessment has been performed to determine the optimum drilling sequence of these various exploration prospects, resulting in the following sequence (subject to funding).

 

·      Wengen - Q2 2023

·      Cortina NE - Q2 2023

Analysis shows that in a P50 resource success case, each exploration prospect offers a highly economic tie-back opportunity to the GBA development. A successful outcome at either of the Wengen or Cortina prospects has been shown to offer the potential to extend the GBA Development Project's plateau production period into the mid- to late- 2030s with enhanced economics.

 

Next Steps

A separate Concept Select Report summarising the Company's findings, as outlined herein, will be submitted for approval to the OGA by 31^st July 2021 in compliance with JOG's commitment under the P2498 licence, which contains Buchan.  Work continues apace with respect to the issuance of tenders for marine surveys to support the Environmental Statement required for the Field Development Plan. Tendering processes for the provision of FEED engineering services is also underway. JOG is currently working towards being ready to enter the FEED phase of the GBA project in Q3 2021, with FID (Final Investment Decision) currently anticipated for H2 2022.

 

With its Concept Select Report finalised, JOG is now in a position to launch its previously announced farm-out process to seek to secure an industry partner for the GBA Development Project.  JOG's Board anticipates that this will be well received by the industry as an exciting investment opportunity, in light of its scale, economics and low carbon production approach, and currently intends to conclude this process before the end of 2021.

 

Enquiries:

Jersey Oil and Gas plc	Andrew Benitz, CEO	C/o Camarco: Tel: 020 3757 4983
Strand Hanson Limited	James Harris Matthew Chandler James Bellman	Tel: 020 7409 3494
Arden Partners plc	Paul Shackleton Benjamin Cryer	Tel: 020 7614 5900
Camarco	Billy Clegg James Crothers	Tel: 020 3757 4983

 

 

Qualified Person's Statement

The information contained in this announcement has been reviewed and approved by Ronald Lansdell, Chief Operating Officer of Jersey Oil & Gas, a qualified Geologist and Fellow of the Geological Society, who has over 40 years' relevant experience within the sector.

 

Notes to Editors:

Jersey Oil & Gas is a UK E&P company focused on building an upstream oil and gas business in the North Sea. The Company holds a significant acreage position within the Central North Sea referred to as the Greater Buchan Area ("GBA"), which includes operatorship and 100% working interests in blocks that contain the Buchan oil field and J2 and Glenn oil discoveries and an 100% working interest in the P2170 Licence Blocks 20/5b & 21/1d  (subject to OGA approval of the acquisition of CIECO V&C UK Limited as announced on 26 November 2020), that contain the Verbier oil discovery and other exploration prospects

JOG's total GBA acreage is estimated by management to contain 190 million barrels of oil equivalent ("mmboe") of discovered P50 recoverable resources net to JOG, in addition to significant exploration upside potential of approximately 220 mmboe of prospective resources in close proximity to our planned Buchan platform. JOG has recently concluded the Concept Select Phase of an FDP for the Greater Buchan Area and plans to progress into Front End Engineering and Design (FEED) later this year.

JOG is focused on delivering shareholder value and growth through creative deal-making, operational success and licensing rounds. Its management is convinced that opportunity exists within the UK North Sea to deliver on this strategy and the Company has a solid track-record of tangible success.

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulation (EU) No. 596/2014 as it forms part of United Kingdom domestic law by virtue of the European (Withdrawal) Act 2018.

This announcement includes "forward-looking statements" which include all statements other than statements of historical facts, including, without limitation, those regarding the Group's financial position, business strategy, plans and objectives of management for future operations, or any statements preceded by, followed by or that include the words "targets", "believes", "expects", "aims", "intends", "will", "may", "anticipates", "would", "could" or similar expressions or negatives thereof. Such forward-looking statements involve known and unknown risks, uncertainties and other important factors beyond the Company's control that could cause the actual results, performance or achievements of the Group to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. Such forward-looking statements are based on numerous assumptions regarding the Group's present and future business strategies and the environment in which the Group will operate in the future. These forward-looking statements speak only as at the date of this announcement. The Company expressly disclaims any obligation or undertaking to disseminate any updates or revisions to any forward-looking statements contained herein to reflect any change in the Company's expectations with regard thereto or any change in events, conditions or circumstances on which any such statements are based unless required to do so by applicable law or the AIM Rules.